Multiple distributed force measurements

ABSTRACT

Methods, computer programs, and systems for detecting at least one downhole condition are disclosed. Forces are measured at a plurality of locations along the drillstring. The drillstring includes a drillpipe. At least one of the forces is measured along the drillpipe. At least one downhole condition is detected based, at least in part, on at least one measured force.

CROSS-REFERENCE TO RELATED APPLICATIONS

This application is a continuation of U.S. patent application Ser. No.12/493,845, filed Jun. 29, 2009 now U.S. Pat. No. 7,962,288 entitled“Multiple Distributed Force Measurements,” by Daniel Gleitman, which, inturn claims priority to commonly owned U.S. Pat. No. 7,555,391, filedMar. 2, 2005, entitled “Multiple Distributed Force Measurements,” byDaniel Gleitman, which, in turn claims priority to commonly owned U.S.provisional patent application Ser. No. 60/550,033, filed Mar. 4, 2004,entitled “Multiple Distributed Sensors Along A Drillpipe,” by DanielGleitman.

BACKGROUND

As oil well drilling becomes increasingly complex, the importance ofcollecting downhole data while drilling increases.

BRIEF DESCRIPTION OF THE DRAWINGS

FIG. 1 shows a system for processing downhole data.

FIG. 2 illustrates a portion of drillpipe with an affixed sensor and acommunications medium.

FIG. 3 illustrates a portion of drillpipe with a force sensor in asensor-module receptacle.

FIG. 4 is a cut-away diagram of the pin-end of a drillpipe joint withforce sensors affixed to the joint.

FIG. 5 is a cut-away diagram of a node sub with a force sensor.

FIG. 6 shows a block diagram for a force sensor.

FIG. 7 shows a block diagram of a drillpipe coupler.

FIGS. 8 and 9 illustrate connectors for sensor couplers and electronicsmodule couplers.

FIG. 10 shows a block diagram of a system for detecting at least onedownhole condition.

FIG. 11 illustrates a borehole.

FIG. 12 illustrates a drillstring tension-versus-depth plots of a set ofdata.

FIG. 13 shows a block diagram of a system for detecting at least onedownhole condition.

FIG. 14 shows a block diagram of a system for identifying, locating, andcharacterizing at least one downhole condition.

FIGS. 15-18 illustrate drillstring tension versus depth for value sets.

FIGS. 19-21 illustrate torque versus depth for value sets.

FIG. 22 illustrates a drillstring tension versus depth measured valueset.

FIGS. 23-24 show block diagrams of systems for additional action basedon detected conditions.

FIG. 25 shows a block diagram of a system for modifying an expectedvalue set.

DETAILED DESCRIPTION

As shown in FIG. 1, oil well drilling equipment 100 (simplified for easeof understanding) may include a derrick 105, derrick floor 110, drawworks 115 (schematically represented by the drilling line and thetraveling block), hook 120, swivel 125, kelly joint 130, rotary table135, drillpipe 140, one or more drill collars 145, one or more MWD/LWDtools 150, one or more subs 155, and drill bit 160. Drilling fluid isinjected by a mud pump 190 into the swivel 125 by a drilling fluidsupply line 195, which may include a standpipe 196 and kelly hose 197.The drilling fluid travels through the kelly joint 130, drillpipe 140,drill collars 145, and subs 155, and exits through jets or nozzles inthe drill bit 160. The drilling fluid then flows up the annulus betweenthe drillpipe 140 and the wall of the borehole 165. One or more portionsof borehole 165 may comprise open hole and one or more portions ofborehole 165 may be cased. The drillpipe 140 may be comprised ofmultiple drillpipe joints. The drillpipe 140 may be of a single nominaldiameter and weight (i.e. pounds per foot) or may comprise intervals ofjoints of two or more different nominal diameters and weights. Forexample, an interval of heavy-weight drillpipe joints may be used abovean interval of lesser weight drillpipe joints for horizontal drilling orother applications. The drillpipe 140 may optionally include one or moresubs 155 distributed among the drillpipe joints. If one or more subs 155are included, one or more of the subs 155 may include sensing equipment(e.g., sensors), communications equipment, data-processing equipment, orother equipment. The drillpipe joints may be of any suitable dimensions(e.g., 30 foot length). A drilling fluid return line 170 returnsdrilling fluid from the borehole 165 and circulates it to a drillingfluid pit (not shown) and then the drilling fluid is ultimatelyrecirculated via the mud pump 190 back to the drilling fluid supply line195. The combination of the drill collar 145, MWD/LWD tools 150, anddrill bit 160 is known as a bottomhole assembly (or “BHA”). Thecombination of the BHA, the drillpipe 140, and any included subs 155, isknown as the drillstring. In rotary drilling the rotary table 135 mayrotate the drillstring, or alternatively the drillstring may be rotatedvia a top drive assembly.

The terms “couple” or “couples,” as used herein are intended to meaneither an indirect or direct connection. Thus, if a first device couplesto a second device, that connection may be through a direct connection,or through an indirect electrical connection via other devices andconnections. The term “upstream” as used herein means along a flow pathtowards the source of the flow, and the term “downstream” as used hereinmeans along a flow path away from the source of the flow. The term“uphole” as used herein means along the drillstring or the hole from thedistal end towards the surface, and “downhole” as used herein meansalong the drillstring or the hole from the surface towards the distalend.

It will be understood that the term “oil well drilling equipment” or“oil well drilling system” is not intended to limit the use of theequipment and processes described with those terms to drilling an oilwell. The terms also encompass drilling natural gas wells or hydrocarbonwells in general. Further, such wells can be used for production,monitoring, or injection in relation to the recovery of hydrocarbons orother materials from the subsurface.

One or more force sensors 175 may be distributed along the drillpipe,with the distribution depending on the needs of the system. In general,the force sensors 175 may include one or more sensor devices to producean output signal responsive to a physical force, strain or stress in amaterial. The sensor devices may comprise strain gauge devices,semiconductor devices, photonic devices, quartz crystal devices, orother devices to convert a physical force, strain, or stress on or in amaterial into an electrical or photonic signal. In certain embodiments,the force measurements may be directly obtained from the output of theone or more sensor devices in the force sensors 175. In otherembodiments, force measurements may be obtained based on the output ofthe one or more sensor devices in conjunction with other data. Forexample, the measured force may be determined based on materialproperties or dimensions, additional sensor data (e.g. one or moretemperature or pressure sensors), analysis, or calibration.

One or more force sensors 175 may measure one or more force components,such as axial tension or compression, or torque, along the drillpipe.One or more force sensors 175 may be used to measure one or more forcecomponents reacted by or consumed by the borehole, such as borehole-dragor borehole-torque, along the drillpipe. One or more force sensors 175may be used to measure one or more other force components such aspressure-induced forces, bending forces, or other forces. One or moreforce sensors 175 may be used to measure combinations of forces or forcecomponents. In certain implementations, the drillstring may incorporateone or more sensors to measure parameters other than force, such astemperature, pressure, or acceleration.

In one example implementation, one or more force sensors 175 are locatedon or within the drillpipe 140. Other force sensors 175 may be on orwithin one or more drill collars 145 or the one or more MWD/LWD tools150. Still other force sensors 175 may be in built into, or otherwisecoupled to, the bit 160. Still other force sensors 175 may be disposedon or within one or more subs 155. One or more force sensors 175 mayprovide one or more force or torque components experienced by thedrillstring at surface. In one example implementation, one or more forcesensors 175 may be incorporated into the draw works 115, hook 120,swivel 125, or otherwise employed at surface to measure the one or moreforce or torque components experienced by the drillstring at thesurface.

The one or more force sensors 175 may be coupled to portions of thedrillstring by adhesion or bonding. This adhesion or bonding may beaccomplished using bonding agents such as epoxy or fasters. The one ormore force sensors 175 may experience a force, strain, or stress fieldrelated to the force, strain, or stress field experienced proximately bythe drillstring component that is coupled with the force sensor 175.

Other force sensors 175 may be coupled to not experience all, or aportion of, the force, strain, or stress field experienced by thedrillstring component coupled proximate to the force sensor 175. Forcesensors 175 coupled in this manner may, instead, experience otherambient conditions, such as one or more of temperature or pressure.These force sensors 175 may be used for signal conditioning,compensation, or calibration.

The force sensors 175 may be coupled to one or more of: interiorsurfaces of drillstring components (e.g. bores), exterior surfaces ofdrillstring components (e.g. outer diameter), recesses between an innerand outer surface of drillstring components. The force sensors 175 maybe coupled to one or more faces or other structures that are orthogonalto the axes of the diameters of drillstring components. The forcesensors 175 may be coupled to drillstring components in one or moredirections or orientations relative to the directions or orientations ofparticular force components or combinations of force components to bemeasured.

In certain implementations, force sensors 175 may be coupled in sets todrillstring components. In other implementations, force sensors 175 maycomprise sets of sensor devices. When sets of force sensors 175 or setsof sensor devices are employed, the elements of the sets may be coupledin the same, or different ways. For example, the elements in a set offorce sensors 175 or sensor devices may have different directions ororientations, relative to each other. In a set of force sensors 175 or aset of sensor devices, one or more elements of the set may be bonded toexperience a strain field of interest and one or more other elements ofthe set (i.e. “dummies”) may be bonded to not experience the same strainfield. The dummies may, however, still experience one or more ambientconditions. Elements in a set of force sensors 175 or sensor devices maybe symmetrically coupled to a drillstring component. For example three,four, or more elements of a set of sensor devices or a set of forcesensors 175 may spaced substantially equally around the circumference ofa drillstring component. Sets of force sensor 175 or sensor devices maybe used to: measure multiple force (e.g. directional) components,separate multiple force components, remove one or more force componentsfrom a measurement, or compensate for factors such as pressure ortemperature. Certain example force sensors 175 may include sensordevices that are primarily unidirectional. Force sensors 175 may employcommercially available sensor device sets, such as bridges or rosettes.

In certain implementations, one or more force sensors 175 may be coupledto drillstring components that are used for drilling and that aresubsequently left in the borehole 165. These drillstring components maybe used in casing-while-drilling (i.e. drilling with casing) operations.The drillstring components may be included in a completed well.

In general, the force sensors 175 convert force into one or moresignals. The one or more signals from the force sensors 175 may beanalog or digital. In certain implementations, one or more force sensors175 may be oriented to measure one or more of tension or compressionalong the drillstring (i.e. with respect to the up-hole/downhole axis).As used herein, “tensile force” means one or more of tension orcompression forces along the drillstring. In these implementations, theforce sensors 175 may be coupled with particular drillstring componentsand may include strain responsive sensor devices (e.g. strain gauges).The output of the force sensor 175 may vary based on the modulus ofelasticity of the material of drillstring component coupled with theforce sensor. This modulus of elasticity may be used when determiningthe force. In certain implementations, other inputs (e.g. tensile areas)may be used to determine tension or compression forces in one or moredrillstring components from the stresses. Similarly, one or more forcesensors 175 may be oriented to measure torque on the drillstring (i.e.about the up-hole/downhole axis). For example, the force sensors 175 maybe coupled to diameter surfaces (e.g. inner or outer diameters) ofdrillstring components and may employ outputs from sensor devices (e.g.,one or more strain gauges) and may consider the shear modulus ofelasticity of the drillstring component material. The torques may bedetermined based on the stresses from the strains and other inputs (e.g.polar moment of inertia of the cross sectional area).

A portion of drillpipe 140 is schematically illustrated in FIG. 2. Theillustrated portion of drillpipe includes interfaces 210 between thejoints that form drillpipe 140. Interfaces 210 may include threadedmechanical connections which may have different inner and outerdiameters as compared to the balance of the drillpipe. One or more ofthe interfaces 210 may include communication interfaces. Signals fromforce sensors 175 are coupled to communications medium 205, which may bedisposed in the drillpipe 140 or external to the drillpipe 140.Drillpipe, such as drillpipe 140, with communications medium 205, maycollectively be referred to as a wired drillpipe.

In one example system, the communications medium 205 may be locatedwithin an inner annulus of the drillpipe 140. The communications medium205 may comprise one or more concentric layers of a conductor and aninsulator disposed within the drillstring. In another example system,the drillpipe 140 may have a gun-drilled channel though at leastportions of its length. In such a drillpipe 140, the communicationsmedium 205 may be placed in the gun-drilled channel. In another examplesystem, the communications medium 205 may be fully or partly locatedwithin a protective housing, such as a capillary tubing that runs atleast a portion of the length of the drillpipe 140. The protectivehousing may be attached or biased to the drillpipe inner diameter orstabilized within the drillpipe bore.

The communications medium 205 may be a wire, a cable, a fluid, a fiber,or any other medium. In certain implementations, the communicationsmedium may permit high data transfer rates. The communications medium205 may include one or more communications paths. For example, onecommunications path may connect to one or more force sensors 175, whileanother communications path may connect another one or more sensorsensors 175. The communications medium 205 may extend from the drillpipe140 to the subs 155, drill collar 145, MWD/LWD tools 150, and the bit160. The communications medium 205 may include physical connectors ormating conductors to complete a transition in the communications medium205 across drillpipe joints and other connections.

The communications medium 205 may transition from one type to anotheralong the drillstring. For example, one or more portions of thecommunications medium 205 may include an LWD system communications bus.One more or portions of the communications medium 205 may comprise a“short-hop” electromagnetic link or an acoustical telemetry link. The“short-hop” electromagnetic links or acoustical telemetry link may beused to interface between drillpipe joints or across difficult-to-wiredrillstring components such as mud motors. In certain implementations,the communications medium may include long-hop (i.e., from a downholetransmitter to a surface receiver) telemetry. For example, the long-hoptelemetry may be mud-pulse telemetry, electromagnetic telemetry throughthe Earth, or acoustic telemetry through the drillstring. The long-hoptelemetry may employ one or more repeaters.

A processor 180 may be used to collect and analyze data from one or moreforce sensors 175. This processor 180 may process the force data andprovide an output that is a function of the processed or unprocessedforce data. This output may then be used in the drilling process. Theprocessor may include one or more processing units that operate together(e.g., symmetrically or in parallel) or one or more processing unitsthat operate separately. The processing units may be in the samelocation or in distributed locations. The processor 180 mayalternatively be located below the surface, for example, within thedrillstring. The processor 180 may operate at a speed that is sufficientto be useful in the drilling process. The processor 180 may include orinterface with a terminal 185. The terminal 185 may allow an operator tointeract with the processor 180.

The communications medium 205 may transition to connect the drillstringto the processor 180. The transition may include a mechanical contactwhich may include a rotary brush electrical connection. The transitionmay include a non-contact link which may include an inductive couple ora short-hop electromagnetic link.

The force sensors 175 may communicate with the processor 180 through thecommunications medium 205. Communications over the communications medium205 can be in the form of network communications, using, for example,Ethernet. Each of the force sensors 175 may be addressable individuallyor in one or more groups. Alternatively, communications can bepoint-to-point. Whatever form it takes, the communications medium 205may provide high-speed data communication between the sensors in theborehole 165 and the processor 180. The speed and bandwidthcharacteristics of the communications medium 205 may allow the processor180 to perform collection and analysis of data from the force sensors175 fast enough for use in the drilling process. This data collectionand analysis may be referred to as “real-time” processing. Therefore, asused herein, the term “real-time” means a speed that is useful in thedrilling process.

A portion of a drillstring component is illustrated in FIG. 3. By way ofexample, the illustrated drillstring component is a joint of drillpipe140. Similar implementation may be applied to one or more of subs 155,collars, MWD/LWD tools 175, or the bit 160. The example drillpipe jointhas an elongated box-end upset section. A sensor-module receptacle 305is defined by a recess in the exterior of the drillpipe joint'selongated upset section, below the rotary shoulder connection threads.The sensor-module receptacle 305 may be any suitable size or shape toengage and retain at least a portion of a force sensor 175. The forcesensor 175 may include an electronics module 310. The sensor-modulereceptacle 305 may also include threading to retain at least a portionof the force sensor 175 (e.g. the electronics module 310) withinsensor-module receptacle 305. The drillpipe 140 may also include one ormore drillpipe couplers, such as drillpipe coupler 315, to couplesignals between portions of the drillstring. Communications medium 205may be disposed in drillpipe 140, and drillpipe couplers such asdrillpipe coupler 315 may couple signals into communications medium 205.When the sensor-module receptacle 305 is empty, asensor-module-receptacle cover may be used to cover the sensor-modulereceptacle 305. An example sensor-module-receptacle cover (not shown)may have an exterior for engaging the sensor-module receptacle 305. FIG.3 shows an example electronics module 310 aligned for insertion into asensor-module receptacle 305.

FIG. 3 shows an example sensor-module-receptacle with electronics module310 removed to highlight remaining details within thesensor-module-receptacle. Example locations (non-limiting) within thesensor-module-receptacle are shown on the right side of FIG. 3 forcoupling of one or more sensor devices 340 which may be elements of aforce sensor 175. The sensor devices may be, for example, strain gaugedevices or sets of strain gauges (e.g. bridges or rosettes). Suchexample locations may be at locations along a wall of sensor-modulereceptacle 305, which may be a substantially cylindrical wall. Examplelocations for mounting sensor devices, may be on the bottom (i.e.radially most inward) surface of sensor-module receptacle 305. One ormore sensor devices may be configured within a sensor-module receptacle305 with any of the sensor device quantities, symmetry, types,directions, orientations, coupling approaches, and other characteristicsof the sensor devices discussed above. Wiring between the sensor devices340 and the electronics modules 310 may be routed through holes orgrooves from one or more sensor devices to electronics module 310, usingconnectors or directly soldering.

The electronics module 310 may have complementary features, such asthreading, to engage the sensor-module receptacle 305 threading. Theelectronics module 310 may have a protective exterior and may haveo-rings 325 to isolate it from the ambient conditions exterior to thedrillpipe 140 which may include the mud flowing around drillpipe 140. Atleast a portion of the electronics module 310 may be inserted andremoved from sensor-module receptacle 305 to permit swapping orreplacement, based on the type of data to be collected in the portion ofthe drillpipe 140 where the force sensor 175 will be located, or formaintenance. The electronics module 310 may include a connector 330 tomate with a connector 335 in the sensor-module receptacle 305.

Force sensors 175 may also be located in the pin ends of drillstringelements, for example drillpipe joints. A cross-sectional diagram of thepin end 405 of a drillpipe joint is shown in FIG. 4. The pin end 405 ofthe joint may include a sensor module receptacle 305. One or more sensordevices may be configured within sensor-module receptacle 305, forexample, with any of the sensor device quantities, symmetry, types,directions, orientations, coupling approaches, wiring, and othercharacteristics of the sensor devices discussed above. One or more forcesensors 175 may be affixed to the exterior of the drillpipe joint. Oneor more force sensor 175 may include one or more sensor devices affixedto the exterior of the drillpipe joint, an electronics module locatedelsewhere (e.g. in a sensor module receptacle 310), and wiring betweenthe two. One or more force sensors 175 or portions of force sensor 175(e.g. sensor devices) may be encased in a covering 410. In certainimplementations, the covering 410 may include, for example, a hermeticelastomer or epoxy. One or more of the force sensors 175 mounted to theexterior of the drillpipe may be located near the pin end upset. One ormore force sensors 175 mounted to the exterior of the drillpipe may belocated on a smaller cross-sectional area section as shown in FIG. 4.Such mounting may provide greater strain for a given force or torque ascompared to mounting on an upset section and may enhance force or torquemeasurement quality (e.g. resolution). In general, one or more forcesensors 175 may be configured to measure one or more of tension,compression, torque, or bending. The pin end 405 insert may include oneor more communications couplers, such as drillpipe coupler 315. Thecommunications medium 205 may be disposed in the drillpipe.

A cross-sectional diagram of an example sub 155 is shown in FIG. 5. Thesub 155 shown in FIG. 5 may include threading to attach between twodrillpipe joints. An elongated box joint 500 of the sub 155 is shown, asan example, with similar implementation possible on other drillstringcomponents. A force sensor 175 is shown comprised of an electronicsmodule 310, one or more sensor devices 340, and wiring 505 between thesensor devices 340 and the electronics module 310. One or more portionsof the exterior of sub 155 may be cut or milled away to form relativelyshallow “flats,” such as flat 510, at one or more locations. One or moreflats 510 may be oriented around the circumference of sub 155. One ormore sensor devices 340 may be adhered to the flats 510. The adheredsensor devices 340 may be protected from the ambient mud with anoverlay. The overlay may be, for example, an epoxy, or an elastomer.Hard facing 515 such as a satellite overlay may also be employed nearthe flats for protection from the borehole wall.

The force sensor 175 may include “dummy” sensor devices proximatelylocated and coupled in a manner to not respond to strain in thedrillstring element. Alternatively, or in addition, one or more sensordevices 340 may be coupled to the inner bore of sub 155. The box-end ofthe sub 155 may be bored back to retain a box-end insert 520. Thebox-end insert 520 may include one or more electronics modules 310.Wiring 505 may be routed from one or more of the sensor devices 340coupled to the exterior of sub 155 through drilled holes and throughhermetic sealing connectors, for connecting or soldering to theelectronics module 310. Wiring 505 may be routed from one or more sensordevices 340 coupled to the inner bore of sub 155 to the electronicsmodule. The electronics module 310 may include a coupler to couple theforce sensor 175 to the communications medium 205.

The sub 155 and box-end insert 520 may include one or more sensordevices 340 configured to measure one or more of axial tension, axialcompression, torque, or bending. The box-end insert may include one ormore communications couplers. The communications medium 205 may bedisposed in the sub 155. As discussed above, the sub 155 may includecommunication equipment.

An example force sensor 175, shown schematically in FIG. 6, includes asensor device 340 to produce a signal indicative of the force itexperiences. The output from the sensor device 340 may be digital oranalog. Depending on the mode of communications used over thecommunications medium 205, the output from the sensor device 340 mayrequire conversion from analog to digital with an analog-to-digitalconverter 610. In certain implementations, the force sensor 175 mayinclude a plurality of analog-to-digital converters 610 to accommodatemultiple sensor devices 340. In other implementations, the force sensor175 may include a multiplexer (not shown) to accommodate multiple sensordevices 340 with fewer analog-to-digital converters 610. After thesensor device 340 has produced a signal indicative of the measuredforce, the signal may be coupled to the communication medium 205 using acommunications coupler, which may include a electronics module coupler615 within the force sensor 175 and may include a drillpipe coupler. Theelectronics module coupler 615 may include a connector 330 for inducinga signal in the drillpipe coupler 705, shown in FIG. 7. The drillpipecoupler may include a connector 335 for engaging the electronics-modulecoupler connector 330. Connectors may include direct electricalconnection and example suitable connectors of this type include thosefrom Kemlon and Greene Tweed, both of Houston, Tex.

The communication coupler, which is the combination of the electronicsmodule coupler 615 and the drillpipe coupler, performs signaltransformations necessary to couple the sensor signal to thecommunications medium 205. One example communication coupler mayre-encode the signal from the sensor device 340 or the analog-to-digitalconverter, include header information, and transmit the signal over thecommunication medium 205.

An example complementary pair of electronics module coupler anddrillpipe coupler connectors 330 and 335 is shown schematically insection view in FIG. 8. The drillpipe-coupler connector 330 includes twoconductive plugs 805 and 810, which will protrude from the drillpipe 140at the base of the sensor-module receptacle 305. The complementarysensor-coupler connector 335 includes two conductive rings 815 and 820.This arrangement allows the connectors 330 and 335 to mate when, forexample, the electronics module sensor 310 is screwed into thesensor-module receptacle 305. In such a configuration, the drillpipecoupler 705 and the electronics module coupler 615 have a directelectrical connection and the drillpipe coupler may be in directelectrical contact with the communications medium 205.

Another example complementary pair of sensor-coupler anddrillpipe-coupler connectors 330 and 335 is shown in FIG. 9. Theelectronics module connector 330 includes an antenna 905 and thedrillpipe-coupler connector includes an antenna 910. In such aconfiguration, the electronics module coupler 615 transmits the signalindicative of the one or more measured properties to the drillpipecoupler using wireless signaling. For example, the sensor and drillpipecoupler may communicate using short-hop telemetry or another wirelesscommunication method. Each of the antennas 905 and 910 may be anyantenna or other transducer capable of providing communication betweenthe electronics module coupler 615 and the drillpipe coupler 705.

In another example system, the electronics module coupler connector 330and the drillpipe-coupler connector 335 may include inductors or coils.The electronics module coupler 615 may pass current through its inductorto create an electromagnetic field indicative of the force sensorsignal. The electromagnetic field, in turn, induces a current in thedrillpipe coupler's inductor. In another example system, the connectors330 and 335 may form two plates of a capacitor allowing a signal to becapacitively induced on the opposing plate. The force sensor 175 or thebase of the sensor-module receptacle 305 may include a coating or insertto provide a dielectric between the connectors 820 and 905 forcapacitive coupling.

Returning to FIG. 6, the components in force sensor 175 may requirepower to operate. In one example system, the necessary power may beprovided by power source 625, which may be a battery, such as a lithiumbattery. In another example system, the necessary power may be suppliedover the communication medium 205 using, for example, Power OverEthernet (POE). In yet another example system, a separate power line maybe run through the drillpipe 205 and taps may be provided for theattached force sensors 175. One or more force sensors 175 may be poweredfrom a central bus with power provided from the surface, or from adownhole central battery module. The power may be generated by, forexample, a downhole generator driven by the mud flow or drillpiperotation, or another power source.

An example system for detecting downhole conditions based on one or moreforce measurements from one or more force sensors 175 is shown in FIG.10. The processor 180 generates an expected value set of expected forcevalues (block 1005). The processor 180 receives one or more forcemeasurements from the force sensors 175 (block 1010). The processor 180may create a measured-value set from the force measurements received andmay determine one or more measured-value gradients (blocks 1015 and1020). The processor 180 may compare the measured force profile with theexpected force profile (block 1025) to detect a downhole condition. Ifthe processor detects a downhole condition (block 1030, which is shownin greater detail in FIG. 13), it may identify, locate, and characterizethe downhole condition (block 1035, which is shown in greater detail inFIG. 14). The processor 180 may perform further actions (block 1040).Regardless of whether the processor 180 detects a downhole condition(block 1030), it may modify the expected-value set (block 1045) and mayreturn to block 1010.

Creating the set of expected force values (block 1005) may includereceiving one or more expected forces from an external source (e.g., auser, a database, or another processor). Creating the expected-value setmay include accessing simulation results such as modeling results. Themodeling to create the expected force values may include torque-and-dragmodeling. The torque-and-drag modeling may consider one or more of thefollowing: mechanical and other properties of the borehole anddrillstring, fluid properties, operations in-process, previous forcemeasurements from the borehole 165 or other boreholes, or othermeasurements. The torque-and-drag modeling may consider the dimensionsand material properties of the drillstring elements. The torque-and-dragmodeling may consider borehole survey data. Other modeling may be usedin creating the expected-force value set, including hydraulics modeling.Other measurements may also be used in creating the expected-force valueset, including pressure measurements from one or more of the standpipe196, points along the drillstring, or points along the borehole 165. Insome implementations, an expected-value set may be created by copyingone or more values from a measured-value set. In other implementationsan expected-value set may be created by using values from ameasured-value set and adjusting or operating upon the values inaccordance with an algorithm or model. Some implementations utilizingmeasured-value sets to create one or more expected-value sets may usemeasured-value sets from a recent time window, an earlier time window,or multiple time windows. Certain example expected-value sets may bederived from trend analysis of measured-value sets, such trends beingobserved or calculated in reference to, for example, elapsed time,circulation time, drilling time, depth, another variable or combinationsof variables.

The expected-value set may include one or more force values at one ormore depths in the borehole 165. The depths may be locations of interestwithin the borehole 165. A set of expected values may be provided ordetermined corresponding to all or a portion of the drillstring pathwithin the borehole 165.

Each expected-value set may represent one or more force profiles. Aforce profile may include a set of two or more forces, and a set of twoor more depths, or ranges of depths, where each force corresponds to adepth or a range of depths. The force profiles may exist, may bemeasurable, and may be modelable along the borehole 165.

Example force profiles may include one or more drillstring axial forceprofiles which may represent tension or compression in the drillstring,or both. Other example force profiles may include one or moreborehole-drag profiles. Borehole-drag profiles may represent the forcesassociated with the borehole resisting axial movement of thedrillstring, and may depend upon one or more of friction profile betweenborehole and drillstring, drillstring dimensions and buoyant weights,borehole path and angles, hook load, and other factors. Borehole-dragprofiles may include static drag (i.e., the force to be overcome tomove) or dynamic drag (i.e., the force resisting movement while moving).Borehole-drag profiles may be calculated or modeled using axial forceprofiles. Other example force profiles may include drillstring torqueprofiles, which may represent the torque at points along the drillstringreflecting torque sources and reaction points including one or more of:the surface rotary drive, the bit-rock interaction, a mud motor, thedrillstring-borehole interaction, and other sources or reaction points.Other example force profiles may include borehole-torque profiles, whichmay represent the forces, acting upon a moment arm, resisting therotation of the drillstring. Borehole-torque profiles may depend uponone or more of: the friction profile between borehole and drillstring,the drillstring dimensions and buoyant weights, the borehole path andangles, the hook load, and other factors. Borehole-torque profiles mayinclude static torque (i.e., the torque to be overcome to beginrotation) or dynamic torque (i.e., the torque resisting rotation whilerotating). Borehole-torque profiles may be calculated or modeled usingone or more of axial force profiles and drillstring torque profiles.Example force profiles may include arithmetic or other combinations orsuperposition of profiles.

Expected force values, or an expected force value set, may be derivedfrom a current (e.g., most recently acquired) set of one or moremeasured forces, a current measured force set, or a current measuredforce gradient. The processor 180 or the user may derive the expectedforce values from these one or more measured forces or measured forcegradients by extrapolating a measured gradient covering a particulardepth range to a larger depth range. Likewise, the processor 180 or theuser may perform such a derivation by interpolating between two measuredgradients.

While drilling the borehole 165, the processor 180 may change theexpected-value set to reflect changes in the well. For example, theprocessor 180 may change the expected-value set to reflect drillingprogress (e.g. increasing depth). The processor 180 may change theexpected-value set to reflect the length and properties of drillstring.The processor 180 may alter the expected-value set to account for one ormore known or unknown drilling process events or conditions. Changes tothe expected-value set may be consistent or inconsistent with modeling,forecasts, or experience.

When generating the expected-value set, the processor 180 may considerone or more factors impacting force on the drillstring including thedimensions of the drillstring (e.g., inner and outer diameters of jointsor other portions of the drillpipe and other drillstring elements),survey path and angles of borehole 165, and dimensions of the borehole165. The processor 180 may also consider one or more depthscorresponding to one or more measured forces within the borehole 165 orthe drillstring. The processor 180 may consider drilling fluidproperties (e.g., flow rates, densities) and whether one or moreportions of the borehole 165 are cased or open hole.

The processor 180 may be provided with or may calculate one or moredepths when calculating the expected-value set. The depths may includeone or more of the following: the true-vertical depth (TVD) (i.e., onlythe vertical component of the depth), and the measured depth (MD) (i.e.,the direction-less distance from the start of the borehole or otherreference point chosen such as ground level, sea level, or rig level, tothe bottom of the borehole or other point of interest along theborehole). The processor 180 may be provided with planned or measuredsurvey station data (e.g., the inclination and azimuth) for one or morepoints along the well path, with corresponding MD or TVD depths, and theprocessor 180 may use the survey station data to calculate a well path.The well path may include inclinations and azimuths for some or allpoints of the well, which may be derived from one or more of actual datainputs at survey stations or interpolations between.

The processor 180 may generate one or more expected-value sets fordifferent drilling process operations. For example, the processor 180may generate one or more expected-value sets for pick-up, slack-off,sliding, rotary drilling with weight-on-bit, sliding drilling,back-reaming, tripping, and for the case where the drillstring isrotating off-bottom. The processor may consider data or planned valuesfor operational parameters such as hook load, rotary RPM, rotary torque,downhole weight-on-bit, downhole torque-on-bit, mud motor pressure drop,or other operational parameters. The mud motor pressure drop may be usedto infer a downhole torque-on-bit. In certain implementations, theexpected-value set is generated dynamically based on the currentdrilling process operation. In other implementations, differentexpected-value sets are generated for different drilling processoperations. In other implantations, an expected-value set is created forone drilling process operation and modified for other drilling processoperations.

An example borehole 1100 that may be modeled by the processor 180 isshown schematically in FIG. 11. The borehole 1100 includes a verticalsegment 1105, a “tangent section” segment 1110 disposed to the verticalportion 1105 at inclination angle 1115, and a horizontal segment 1120. Aborehole 1100 with a cased vertical segment 1105 of 3000 feet, anuncased segment 1110 of 3000 feet, an inclination angle 1115 of 60degrees, and an uncased horizontal segment 1120 of 1800 feet will serveas the basis of upcoming examples. This example borehole description issimplistic, but demonstrative for purposes of discussing examples of thesystem. Between the vertical and tangent sections, and between thetangent and horizontal sections are assumed to be smooth curves, butthey are not shown for simplicity. Actual boreholes may include othergeometric features including azimuthal curvatures. Curve sections, inone or both of inclination and azimuth, may form transitions betweenstraight segments or the curve sections may take the place of one ormore straight segments. Other example boreholes may include complex wellpaths. Other borehole features may be considered when modeling theborehole 165. Such features may include hole diameters, formation types,casing type, borehole tortuosity, friction factors, and mud type. Anexample drillstring may be modeled by the processor 180 within exampleborehole 1100. The modeling may include one or more intervals ofdrillstring elements (e.g. drillpipe, collars, MWD tools) of one or moreunit weights (e.g. pounds per foot), and one or more dimensions (e.g.outer diameters). A simple example drillstring which may be modeled maybe predominantly composed of multiple joints of a single weightdrillpipe. Other example drillstrings may be modeled including severalintervals of different weight drillpipe and collars, optionally with MWDtools, all with their own dimensions.

An example expected-value set based on borehole 1100 having dimensionsdescribed above is shown in FIG. 12. The lines shown in FIG. 5 mayrepresent underlying data points (e.g., tension-versus-depth). Thisexample expected-value set assumes that the drillstring is engaged inpick-up. The expected value set is shown piecewise for each of thecorresponding borehole segments and the interface between the portions(i.e., segments 1210, 1215, and 1220) of the expected-value set is notshown in the graph. In certain implementations, the curve sectionsbetween the portions may be generated. The expected-value set 1205 showsdrillstring tension versus the percentage of measured depth to the totaldepth of the drillstring in the borehole. Segment 1210 represents thedrillstring tension through the borehole segment 1120. Segment 1215represents drillstring tension through the 60 degree borehole segment1110. Segment 1220 represents drillstring tension in the verticalsegment 1105.

Returning to FIG. 10 and referring to system elements shown in FIG. 1,once the drillstring has entered to the borehole 165, the processor 180receives force measurements from one or more force sensors 175 (block1010). The processor 180 creates a measured-value set (block 1015). Theprocessor 180 may determine one or more measured-value gradients (i.e.,the change in measured force-versus-depth). Certain exampleimplementations include at least three force sensors 175 to provide atleast two gradients. Certain example implementations include at leastone gradient corresponding to each of at least two sections of thedrillstring or borehole, such sections corresponding, for example, to:(a) ranges of hole angle (e.g. vertical, curve, tangent, horizontalsections); (b) lengths of common drillstring element type (e.g. overcollars, over heavyweight pipe, over drillpipe); (c) lengths ofdifferent casing diameters or hole diameters; (d) lengths of boreholeexposure to one or more particular formation types; or (e) cased versusopen hole.

In certain example implementations, the processor may not determine theone or more gradients (block 1020). For example, if the processor 180 isdetecting at least one downhole condition which can be detected byobserving absolute differences between one or more measured forces, orbetween one or more measured forces and one or more expected forces, itmay not determine the one or more gradients.

The number and location of the force sensors 175 may affect the numberof force-versus-depth data points available in the measured-value set.Additionally, a force sensor 175 that is moved from one location toanother (e.g. during drilling or tripping) may provide multiple datapoints in a measured-value set.

Certain example implementations may include the creation of ameasured-value set (block 1015) inclusive of one or more forcemeasurements from surface sensors not actually on the drillstring, asdescribed earlier. In such implementations one or more forcemeasurements (e.g. tension, torque) corresponding to the top of thedrillstring may be inferred from the surface sensor force measurements.At least two force-versus-depth data points may be used to determine ameasured-value gradient. Where actual force-versus-depth data points arenot available, the processor 180 may estimate one or moreforce-versus-depth data points. The processor 180 may estimateforce-versus-depth data points by interpolating between data points,extrapolating gradients, or determining transitions between gradients.

In certain example system, the measured-value set of forces (e.g.,measured tension/compression or torque values), the expected-value setof forces (e.g., expected tension/compression or torque values), or bothmay be displayed to the operator using the terminal 185. For example,the measured-value set may be juxtaposed to the expected-value set usingthe terminal 185, allowing the user to manually detect, identify,characterize, or locate a downhole condition. The measured-value setsand the expected-value sets may be presented to the user in a graphicalformat (e.g., a chart, log, plot, or series of plots) or in a textualformat (e.g., a table of values). Certain example systems may includepresenting an evolution of one or more of the measured-value sets andthe expected-value sets to the user. For example, the system may displaya series of plots to the user to demonstrate the evolution of one ormore of the measured-value sets and the expected-value sets. The systemmay display an evolution of both the measured-value set and theexpected-value set. Certain evolutions may be evolutions over time,depth, or other variables or combinations of variables.

Individual measured forces (e.g., tensions/compressions or torques) inthe measured-value set may be measured in a short time window (e.g.seconds) for minimized delay in detecting of conditions. In manyimplementations individual measured forces in the measured-value set maybe measured substantially simultaneously. As used herein, “substantiallysimultaneously” means only that the measurements are taken in the sametime period during which conditions are not expected to changesignificantly, in the context of the particular operational process.Many downhole conditions (e.g., cuttings build-up) may be detected usingmeasured-value sets, the values of which are obtained in a time windowof minutes. During transient operational processes such as tripping, andfor detection of events or conditions which have a faster time constant,a shorter time window for collecting and analyzing a measured-value setmay be preferred. Individual measured forces along the drillstring inthe measured-value set may be measured in a short time window (e.g.within a second or less), and such short-time-window measurement processmay then be repeated one or more additional times during a larger timewindow of seconds to minutes. An averaged measured-value set may becreated from averaging the multiple values for each force sensor. Otherstatistics may be developed for each measured force in themeasured-value set. The statistics may include, for example, minimum andmaximum values and standard deviation. Averaged values, optionally inconjunction with further statistics, may be preferred for use duringcertain operational processes in which conditions are anticipated tohave a dynamic element (e.g. stick or slip during drilling).

Individual measured forces in the measured-value set may be measuredsequentially. In some example implementations, the sequence by which theforces are measured may be controllable by, for example, the processor180. For example, the sequence by which the forces are measured may bedetermined by an algorithm based on drilling conditions or otherfactors.

Example systems may provide measured versus expected forces, profiles,or gradients in different operational processes of well construction,including, for example and without limitation: on-bottom rotarydrilling, sliding, tripping, off-bottom circulating, circulating up akick, circulating pills or transitioning mud types, picking up, andslacking off.

An example system for determining if there is a downhole condition(block 1030) is shown in FIG. 13. In general, a downhole condition mayinclude any regular or irregular, static or dynamic, condition or eventalong the drillstring or in the wellbore. Example downhole conditionsmay include, but are not limited to, one or more of the following: aborehole deviation, a hole restriction, a cuttings build-up,differential sticking, a wash-out, or an influx. The processor 180 maydetermine if one or more force measurements are out of range (block1305), and if so it returns “Y” (block 1310), otherwise it returns “N”(block 1315).

The processor 180 may determine whether any of the quantities are out ofrange (blocks 1305) by determining if the difference between themeasured property (e.g., measured tension/compression, toque,tension/compression gradient, or torque gradient) and the expectedproperty (e.g., expected tension/compression, torque,tension/compression gradient, or torque gradient) is greater than amaximum delta for the property.

In certain implementations, the maximum delta may be determinedautomatically by the processor 180. In other implementations the maximumdelta may be input by an operator. In other implementations, the maximumdelta may be obtained from a separate processor or model. In certainimplementations, the maximum delta may be determined by an operator oran independent model based on one or more measured forces.

The maximum delta determination may be based on an absolute differenceversus an expected value, or it may be based on a percentage deviationfrom the expected value. The maximum delta may be based upon a function.For example, the maximum delta may increase or decrease with depth. Themaximum delta may vary over a depth range or over an operational phase.The maximum delta determination may also be dependant on time. Incertain implementations, a difference between a measured force and anexpected force exceeding the maximum delta may be not be acted on unlessit persists for a particular duration or longer. The maximum delta mayinclude one or more statistical criteria, for example it may include amean, average, or standard deviation of collected deltas over a chosenduration.

Returning to FIG. 10, if the processor 180 determines that there is nota downhole condition (block 1030) it may modify the expected-value set(block 1045) and return to block 1005. In certain implementations, theprocessor may not execute block 1045 without operator input (e.g.,review, approval, input, or intervention). In other implementations,block 1045 may be executed without operator intervention. In one examplesystem, the processor 180 modifies the expected-value set based on moreor more parameters or parameter sets (e.g. actual force gradients)observed or measured downhole. Such an update may provide accounting inthe new expected-value set for new or updated circumstances (e.g.increased hole depth, added joint of drillpipe, changed hook-load,changed fluid density, changed rotary RPM, and/or changed rate ofpenetration) which are not deemed downhole conditions (block 1030).

If the processor 180 determines that there is a downhole condition(block 1030), it may identify the condition (e.g. determine the typecondition detected), it may characterize the downhole condition (e.g.determine the magnitude or other properties of the downhole condition),and it may locate the position of the downhole condition (e.g. determinethe depth or depth interval of the detected condition) (block 1035), andit may take additional actions (block 1040).

An example system for identifying, locating, and characterizing at leastone downhole condition (block 1035) is shown in FIG. 14. The processor180 may identify and locate a borehole deviation (block 1405). Theprocessor 180 may identify and locate a cuttings build-up (block 1410).The processor 180 identify and locate other conditions (block 1415). Theprocessor may characterize the identified conditions (block 1420). Theprocessor may return one or more of the identification, location, andcharacteristics of detected downhole conditions (block 1425).

The identification and location of downhole conditions are demonstratedby reference to example expected- and measured-value sets in FIGS.15-22. FIG. 15 shows an example expected-value set (1505) and an examplemeasured value set (1510) of drillstring tension for a drillstring nearbottom of the borehole, engaged in pick up. The vertical axis representsthe borehole measured depth as a percentage basis of the total measureddepth. The expected-value set (1505) may correspond to the borehole pathof FIG. 11, and may represent drillstring tension values expected (e.g.from user input, modeling, or earlier measurements) along thedrillstring length. More specifically, the expected-value set (1505) mayrepresent:

-   -   near-zero tension expected at the bit;    -   an interval of an expected particular gradient (1501)        representing increasing drillstring tension with increasing        distance from borehole bottom, corresponding to the cumulative        (from drillstring bottom) frictional drag along the portion of        the drillstring in the horizontal hole section;    -   another interval of another expected particular gradient (1502)        representing increasing drillstring tension with increasing        distance from hole bottom, corresponding to: (a) the cumulative        (from this interval's bottom) frictional drag along the portion        of the drillstring in the tangent section, plus (b) the        cumulative (from this interval's bottom) buoyant weight        component of the drillstring supported from above by the        drillstring itself (i.e. not supported by the borehole),        plus (c) the offset corresponding to the total tension at the        bottom of this tangent interval of drillstring resulting from        the intervals below; and    -   a third major interval of third expected particular gradient        (1503) of increasing drillstring tension with increasing        distance from hole bottom, corresponding to: (a) the cumulative        (from this interval's bottom) buoyant weight component of the        drillstring supported from above by the drillstring itself (i.e.        the hanging weight) along the vertical borehole section,        plus (b) the offset corresponding to the total tension at the        bottom of this vertical interval of drillstring resulting from        the intervals below.

The offset difference in the expected-value set (1505) and measuredvalue set (1510) may be indicative of a downhole condition. Thedivergence between the expected value set and measured value set overthe range shown by 1515 may be indicative of the location of thedownhole condition. The difference in the expected-value andmeasured-value gradient over the range shown by 1515 may be indicativeof a cutting build-up in the mid-horizontal section 1120 of the borehole1100. The processor 180 may observe the offset between theexpected-value set and measured value set and may indicate existence ofa likely downhole condition. The processor 180 may observe thedivergence between the expected value set and measured value set overthe range shown by 1515 and it may indicate a likely location of thedownhole condition (around measured depth range of 1515). The processor180 may observe this gradient difference and identify the condition as alikely cutting-build up.

The cuttings build-up in the mid-horizontal section may increase thefrictional drag over the interval of cuttings build-up, thus increasingthe tension gradient (i.e. the change in tension per change in measureddepth) measured over that interval. An increased tension gradient (fromany source) over an interval may tend to increase the overall tensionload measured during pick-up measured at locations from that interval upto surface, which may result in an offset difference as also shown inFIG. 15. The processor 180 may further determine that the likelylocation of the cutting build-up is in the depth range corresponding tothe diverging gradients between the measured- and expected-value sets(e.g., range 1515).

FIG. 16 shows an example expected-value set (1605) and an examplemeasured value set (1610) of drillstring tension for a drillstring nearbottom of the borehole engaged in slack off. The expected-value set mayresult from modeling, user input, or measuring in a similar manner tothe expected-value set determination associated with FIG. 15. In certainwellbore geometries, such as horizontal sections, the expecteddrillstring tension values may be negative (e.g., indicating.compression) in certain drillstring intervals during operations such asslack off. The existence of an offset difference between theexpected-value set (1605) and measured value set (1610) may beindicative of a downhole condition. The divergence between the expectedvalue set and measured value set over the range shown by 1615 may beindicative of the location of the downhole condition. The difference inthe expected-value and measured-value gradients over the range shown by1615 may be indicative of cuttings build-up in the mid-horizontalsection 1120 of the borehole 1100. The processor 180 may observe theoffset between the expected-value set and measured value set and mayindicate existence of a likely downhole condition. The processor 180 mayobserve the divergence between the expected value set and measured valueset over the range shown by 1615 and it may indicate a likely locationof the downhole condition (around measured depth range of 1615). Theprocessor 180 may observe this gradient difference and identify thecondition as a likely cutting-build up. The processor 180 may furtherdetermine that the likely location of the cutting build-up is in thedepth range corresponding to the diverging gradients between themeasured- and expected-value sets (e.g., range 1615).

FIG. 17 shows an example expected-value set (1705) and an examplemeasured value set (1710) of drillstring tension for a drillstringengaged in sliding, for example during directional drilling. Often indirectional drilling, the driller will slack off as required to obtain asufficient downhole weight-on-bit to drill. The sufficient downholeweight-on-bit may be determined and controlled indirectly by, forexample, monitoring a standpipe pressure increase corresponding to adesired mud motor torque or by monitoring the rate of penetration. Thesliding operation of FIG. 17 is similar to the slack off operation ofFIG. 16, with the addition of weight (i.e. drillstring compression) onbit. The measured value set of FIG. 17 may be obtained while slidingdrilling. As in the slack off discussion, the existence of an offsetdifference between the expected-value set (1705) and measured value set(1710) may be indicative of a downhole condition. The divergence betweenthe expected value set and measured value set over the range shown by1715 may be indicative of the location of the downhole condition. Thedifference in the expected-value and measured-value gradients over therange shown by 1715 may be indicative of cuttings build-up in themid-horizontal section 1120 of the borehole 1100. The processor 180 mayobserve the offset between the expected-value set and measured value setand may indicate existence of a likely downhole condition. The processor180 may observe the divergence between the expected value set andmeasured value set over the range shown by 1715 and it may indicate alikely location of the downhole condition (around measured depth rangeof 1715). The processor 180 may observe this gradient difference andidentify the condition as a likely cutting-build up. The processor 180may determine that the likely location of the cutting build-up is in thedepth range corresponding to the diverging gradients between themeasured- and expected-value sets (e.g., range 1715).

FIG. 18 shows an example expected-value set (1805) and an examplemeasured value set (1810) of drillstring tension for a drillstringengaged in pick up. As in the discussion of pick up with respect to FIG.15, the existence of an offset difference between the expected-value set(1805) and the measured value set (1810) may be indicative of a downholecondition. The divergence between the expected value set and measuredvalue set over the range 1815 may be indicative of the location of thedownhole condition. However, in contrast to the pick up discussionrelating to FIG. 15, the divergence between the expected- andmeasured-value sets occurs in a step-change at 1815. In certainsituations, the step-change 1815 may not be as pronounced as the exampleshown in FIG. 18. The step-change in the expected-value and measuredvalue sets at 1815 may be indicative of a borehole deviation in thetangent section 1110 of the borehole 1100. A borehole deviation mayinclude any relatively short interval of deviation from the expectedborehole cylindrical shape. Examples of possible borehole deviationsinclude, for example, and without limitation: a deformed or damagedportion of casing, a borehole obstruction, a swelled shale, a sluffed-inhole section, a ledge, a large dog-leg, or a key-seat. The processor 180may observe the offset between the expected-value set and measured valueset and may indicate existence of a likely downhole condition. Theprocessor 180 may observe the divergence between the expected value setand measured value set over the range shown by 1815 and may indicate alikely location of the downhole condition around the measured depthrange of 1815. The processor 180 may observe this difference between themeasured and expected drillstring tension to represent a step-change andidentify the condition as a borehole deviation. The processor 180 maydetermine that the likely location of the borehole deviation at or aboutthe depth corresponding to the step-change 1815.

FIG. 19 shows an example expected-value set (1905) and an examplemeasured value set (1910) of drillstring torque for a drillstringengaged in rotary drilling with about 5,000 foot-pounds of weighton-bit. In contrast to the earlier plots (FIG. 15-18) the horizontalaxis in FIG. 19 represents drillstring torque (not tension), and theexpected-value set (1905) may represent drillstring torque valuesexpected (e.g. input by a user, modeled, or measured earlier) along thedrillstring length. More specifically, the expected-value set (1905) mayrepresent:

-   -   expected torque-on-bit while rotary drilling (e.g., 5,000        foot-pounds);    -   an interval of an expected particular gradient (1901)        corresponding to increasing drillstring torque with increasing        distance from borehole bottom, corresponding to: (a) the        cumulative (from drillstring bottom) torque consumed by the        borehole (i.e. frictional borehole-torque) along the portion of        the drillstring in the horizontal hole section, plus (b) an        offset corresponding to the expected bit torque;    -   another interval of another expected particular gradient (1902)        corresponding to increasing drillstring torque with increasing        distance from hole bottom, corresponding to: (a) the cumulative        (from this interval's bottom) frictional borehole-torque along        the portion of the drillstring in the tangent section, plus (b)        an offset corresponding to the total drillstring torque at the        bottom of this tangent interval of drillstring resulting from        the intervals below; and    -   a third major interval of third expected particular gradient        (1903) of increasing drillstring torque with increasing distance        from hole bottom, corresponding to: (a) the cumulative (from        this interval's bottom) frictional borehole-torque along the        portion of the drillstring in the vertical section (expected in        this example to be near zero in vertical section), plus (b) the        offset corresponding to the total drillstring torque at the        bottom of this vertical interval of drillstring resulting from        the intervals below.

The offset difference in the expected-value set (1905) and measuredvalue set (1910) may be indicative of a downhole condition. Thedivergence between the expected value set and measured value set overthe range shown by 1915 may be indicative of the location of thedownhole condition. The difference in the expected-value andmeasured-value gradient over the range shown by 1915 may be indicativeof a cutting build-up in the mid-horizontal section 1120 of the borehole1100. The processor 180 may observe the offset between theexpected-value set and measured value set and may indicate existence ofa likely downhole condition. The processor 180 may observe thedivergence between the expected value set and measured value set overthe range shown by 1915 and it may indicate a likely location of thedownhole condition (around measured depth range of 1915).

The processor 180 may observe the gradient difference between theexpected- and measured-value sets and identify the condition as a likelycutting-build up. Such cuttings build-up may increase the frictionaldrag over the interval of cuttings build-up, thus increasing the torquegradient (i.e. the change in torque per change in measured depth)measured over that interval. An increased torque gradient (from anysource) over an interval would tend to increase the overall torque loadmeasured during rotation measured at locations from that interval up tosurface, which may result in an offset difference as also shown in FIG.19. The processor 180 may further determine that the likely location ofthe cutting build-up is in the depth range corresponding to thediverging gradients between the measured- and expected-value sets (e.g.,range 1915). The processor 180 may observe this gradient difference andidentify the condition as a likely cutting-build up.

FIG. 20 shows an example expected-value set (2005) and an examplemeasured value set (2010) of drillstring torque for a drillstringrotating off-bottom. Drillers sometimes pick up off bottom and rotate toobserve the surface torque, or condition the hole. The FIG. 20 rotatingoff-bottom is operation is similar to the rotary drilling operation ofFIG. 19, but without the weight-on-bit and associated torque of thebit/formation interaction. Similarly to the rotary drilling discussion,the existence of an offset difference between the expected-value set(2005) and measured value set (2010) may be indicative of a downholecondition. The divergence between the expected value set and measuredvalue set over the range shown by 2015 may be indicative of the locationof the downhole condition. The difference in the expected-value andmeasured-value gradients over the range shown by 2015 may be indicativeof cuttings build-up in the mid-horizontal section 1120 of the borehole1100. The processor 180 may observe the offset between theexpected-value set and measured value set and may indicate existence ofa likely downhole condition. The processor 180 may observe thedivergence between the expected value set and measured value set overthe range shown by 2015 and it may indicate a likely location of thedownhole condition (around measured depth range of 2015). The processor180 may observe this gradient difference and identify the condition as alikely cutting-build up. The processor 180 may determine that the likelylocation of the cutting build-up is in the depth range corresponding tothe diverging gradients between the measured- and expected-value sets(e.g., range 2015).

FIG. 21 shows an example expected-value set (2105) and an examplemeasured value set (2110) of drillstring torque for a drillstringengaged in off-bottom rotation. Similarly to the earlier rotatingoff-bottom discussion relating to FIG. 20, the existence of offsetdifference between the expected-value set (2105) and measured value set(2110) may be indicative of a downhole condition. The divergence betweenthe expected value set and measured value set over the range shown by2115 may be indicative of the location of the downhole condition.However in contrast to the discussion relating to FIG. 20, thedivergence between the expected- and measured-value sets occurs in astep-change at 2115. In certain situations, the step-change 2115 may notbe as pronounced as the example shown in FIG. 21. The step-change in theexpected-value and measured value sets at 2115 is indicative of a likelyborehole deviation in the tangent section 1110 of the borehole 1100.

The processor 180 may observe the offset between the expected-value setand measured value set and may indicate existence of a likely downholecondition. The processor 180 may observe the divergence between theexpected value set and measured value set over the range shown by 2115and it may indicate a likely location of the downhole condition (aroundmeasured depth range of 2115). The processor 180 may observe thisdifference between the measured and expected drillstring torque torepresent a step-change and identify the condition as a boreholedeviation. The processor 180 may determine that the likely location ofthe borehole deviation at or about the depth corresponding to thestep-change 2115.

The downhole conditions may also be characterized by the processor 180(block 1420). Such characterization may include the determination of alikely magnitude range of the condition. The magnitudes of the measuredand expected force values and measured and expected-value gradients maybe indicative (e.g., analytically through known relationships orempirically) of the characteristics of the condition. For example, theparticular changes in forces or gradients may be used to estimate arevised effective friction factor for an interval. A particular changein forces or gradients may be used to estimate a particular percentagevolume or cross sectional area of borehole filled in by cuttings in acuttings bedded interval. In other examples, processor 180 maycharacterize the interval length of a borehole deviation such as aswelling shale. In yet other examples, the processor 180 maycharacterize the criticality (e.g. from a drill string integritystandpoint) of a borehole deviation such as a keyseat or severe dogleg.The processor 180 may use additional force data from force sensors alongthe drillstring, such as bending forces, in certain characterizations.

The processor 180 or the user may use a combination of measured forcetypes in detecting, identifying, locating, or characterizing one or moredownhole conditions. For example, the processor 180 or the user may useone or more of the following to detect, identify, locate, orcharacterize a downhole condition: the measured tensile force data andassociated expected data, and measured torque data and associatedexpected data, tensile force and torque gradients and respectivegradient differences. As can be seen from FIGS. 15 and 20 for example, asingle condition (cuttings build-up in the horizontal in these twoexamples) may result in measured tensile force data sets, and measuredtorque data sets, which correlate with each other. The processor 180 orthe user may use torque and tension data together to provide greaterassurance of the detection, identification, locating, or characterizingof a downhole condition. Similarly, the processor 180 or the user maycorrelate the same measured force type (e.g. tension), as measured indifferent but sequential operational process (e.g. pick-up andslack-off).

The processor 180 may use other data from drilling rig site sensors anddrillstring sensors to detect, identify, locate, or characterize one ormore downhole conditions. For example, pressure sensor measured valuesets from pressure sensors along the drillstring and expected pressurevalue sets, differences between the pressure sets, gradients ofrespective pressure sets, and pressure gradient differences, may forcertain downhole conditions be depth-correlated with respective forcesensor value sets, their differences, gradients, and gradientdifferences. In another example, formation log data (e.g. from anMWD/LWD tool 150 being run on the drillstring) may be depth correlatedwith certain downhole conditions. For example, as discussed with respectto FIG. 21, an increased torque versus expected torque may be detectedin a short interval, indicating and locating a likely boreholedeviation. Continuing with the example, the addition of MWD/LWD gammaray log data may provide specific indications of a shale at a the samedepth of the condition. The condition then may be identified withgreater confidence as a swelling shale rather than another type ofborehole deviation.

Certain additional downhole conditions may be detected, identified,located, or characterized by similar techniques. Example conditions thatmay be detected are lost circulation, which may cause mild differentialsticking (i.e. not to the point of a stuck drillstring) or a stuck drillsting. Multiple force measurements may be made along the drillstring,and compared to expected values, in the process of getting a drillstringunstuck. Such a process may involve applying one or more of torque,tension, compression, or impact (e.g. jarring) on the drillstring fromthe surface. The transmission of such torque, tension, compression, orimpact down the drillstring to the stuck point may be subject to similarborehole drag, borehole-torque, and borehole conditions consumingportions of the transmitted forces. Comparing the expected and measuredforces along the drillstring may be used to improve the control andefficacy of such processes.

As noted earlier, in certain implementations, measured-value sets may beused directly to provide one or more expected values or anexpected-value set for purposes of the methods discussed. For examplethe detection, identification, location, and characterization of aborehole deviation such as the deviation discussed with regard to FIG.18, may be performed with one or more expected values derived directlyfrom the measured value set. FIG. 22 shows the measured value set fromFIG. 18 (1805, which is shown as a solid line in this figure) ofdrillstring tension for a drillstring engaged in pick up. The expectedvalue set is omitted from FIG. 22 The processor 180 or the user maydetect existence of a downhole condition based upon the presence of arelatively abrupt change in the measured gradient (1815). The processor180 or user may extrapolate the measured value gradient of depthinterval (2205), uphole to the depth interval of abrupt change inmeasured gradient 1815, to establishing one or more expected values oran expected value gradient over interval 2210 to compare with themeasured values over the range 2210. The principles of this example maybe applied to other example implementations of the invention.

The processor 180 may perform additional actions after detecting adownhole condition (block 1040). As shown in FIG. 23, the additionalactions may include one or more of the following:

sending an alarm (block 2305), offering advice on actions to theoperator (e.g. shut-in the borehole, change fluid density or otherproperties, change flow rate, jar, change rotary speed, short trip (e.g.for hole cleaning) (block 2310), or sending a control signal to surfaceor downhole rig equipment or tools responsive to the condition (block2315). As shown in FIG. 24, for example, the control signal may causethe surface or downhole rig equipment to trip to the location of aproblem within the borehole, (block 2405) for example to clean up aborehole obstruction. The control signal may additionally oralternatively cause other automated actions. These actions may include,for example: shutting-in the borehole, changing fluid density or otherproperty, changing flow rate, jarring, changing rotary speed, or shorttripping.

As noted earlier, in certain implementations one or more of themeasured-value set of forces (e.g., measured tension/compression ortorque values) and the expected-value set of forces may be provided tothe user for manual interpretation through comparison of tables, plots,logs, graphs, or the like. In these cases the processor 180 may be usedin the collection of measured data, and the user may manually (e.g.,without reliance on the processor) perform the steps outlined above ofdetecting, identifying, locating, and characterizing a downholecondition. In these cases the processor 180 may be used in thecollection of measured data and the displaying or otherwise providingsuch data in the context of expected values, and the user may manuallyperform the steps outlined above of detecting, identifying, locating,and characterizing a downhole condition.

The processor 180 may also modify the expected-value set (block 1045),as shown in FIG. 25. The processor 180 may modify the expected-value setto account for a detected downhole condition (block 2505). The processor180 may modify the expected-value set to account for other factors, suchas those discussed with respect to determining the expected value set(block 2510).

The present invention is therefore well-adapted to carry out the objectsand attain the ends mentioned, as well as those that are inherenttherein. While the invention has been depicted, described and is definedby references to examples of the invention, such a reference does notimply a limitation on the invention, and no such limitation is to beinferred. The invention is capable of considerable modification,alteration and equivalents in form and function, as will occur to thoseordinarily skilled in the art having the benefit of this disclosure. Thedepicted and described examples are not exhaustive of the invention.Consequently, the invention is intended to be limited only by the spiritand scope of the appended claims, giving full cognizance to equivalentsin all respects.

What is claimed is:
 1. A method of analyzing one or more downholeproperties, comprising: receiving a plurality of force measurements,each corresponding to a location along a drillstring, the drillstringcomprising a drillpipe, and where at least one force measurementcorresponds to a location along the drillpipe; performing at least oneaction based, at least in part, on the at least one force measurement;wherein at least one of the force measurements comprise at least one ofa torque measurement or a tensile force measurement.
 2. The method ofclaim 1, where performing at least one action based, at least in part,on the at least one force measurement, further comprises: performing atleast one action based, at least in part, on at least three forcemeasurements.
 3. The method of claim 1, further comprising: measuringforce at a plurality of locations along the drillstring, where forces attwo or more locations are measured substantially simultaneously.
 4. Themethod of claim 1, further comprising: identifying at least one downholecondition.
 5. The method of claim 1, further comprising: locating atleast one downhole condition.
 6. The method of claim 1, furthercomprising: characterizing at least one downhole condition.
 7. Themethod of claim 1, further comprising: receiving at least one pressuremeasurement, wherein the pressure measurement corresponds to a locationalong the drillstring; and wherein detecting at least one downholecondition is based, at least in part, on the pressure measurement. 8.The method of claim 7, further comprising: identifying at least onedownhole condition, based, at least in part, on the pressuremeasurement.
 9. The method of claim 7, further comprising: locating atleast one downhole condition, based, at least in part, on the pressuremeasurement.
 10. The method of claim 7, further comprising:characterizing at least one downhole condition, based, at least in part,on the pressure measurement.
 11. The method of claim 1, where performingone or more actions in response to the detected downhole conditioncomprises tripping the drillstring to a location of the downholecondition.
 12. The method of claim 1, where performing one or moreactions in response to the detected downhole condition comprises one ormore of: adjusting a mud property; and adjusting flow rate.
 13. Themethod of claim 1, where performing one or more additional actions inresponse to the detected downhole condition comprises shutting-in theborehole.
 14. The method of claim 1, where performing one or moreadditional actions in response to the detected downhole conditioncomprises one or more of: short-tripping; jarring; and adjusting rotaryRPM.
 15. A measurement-while-drilling system for collecting andanalyzing one or more force measurements, comprising: a plurality offorce sensors to measure forces at a drillstring, where at least oneforce sensor is located along a drillpipe; a processor; and a memory,the memory including executable instructions that, when executed, causethe processor to: cause at least one additional action to be performedbased, at least in part, on at least one measured force; wherein atleast one of the force measurements comprise at least one of a torquemeasurement or a tensile force measurement; and wherein at least one ofthe force sensors is coupled to the processor.
 16. Themeasurement-while-drilling system of claim 15, wherein the executableinstructions further cause the processor to: identify at least onedownhole condition.
 17. The measurement-while-drilling system of claim15, wherein the executable instructions further cause the processor to:locate at least one downhole condition.
 18. Themeasurement-while-drilling system of claim 15, further comprising: atleast one pressure sensor to measure a pressure at a location along thedrillstring; and wherein the executable instructions further cause theprocessor to: cause at least one additional action to be performedbased, at least in part, on the measured pressure.
 19. Themeasurement-while-drilling system of claim 15, wherein the executableinstructions that cause at least one additional action to be performedbased, at least in part, on at least one measured force further causethe processor to: cause the system to trip the drillstring to a locationof the downhole condition.
 20. The measurement-while-drilling system ofclaim 15, wherein the executable instructions cause at least oneadditional action to be performed based, at least in part, on at leastone measured force further cause the processor to: cause the system toperform at least one of: adjusting a mud property; or adjusting flowrate.
 21. A method comprising: receiving a plurality of forcemeasurements, each corresponding to a location along a drillstring, thedrillstring comprising a drillpipe, and where at least one forcemeasurement corresponds to a location along the drillpipe; displaying atleast one graphical representation of one or more of the receivedplurality of force measurements; wherein at least one of the forcemeasurements comprise at least one of a torque measurement or a tensileforce measurement.
 22. The method of claim 21, further comprising:determining an expected-value set comprising a plurality of expectedforces and corresponding depths; and wherein displaying at least onegraphical representation of one or more of the received plurality offorce measurements, further comprises displaying a graphicaljuxtaposition of the measured-value set and the expected-value set. 23.A method of analyzing one or more downhole properties, comprising:receiving a plurality of force measurements, each corresponding to alocation along a drillstring, the drillstring comprising a drillpipe,and where at least one force measurement corresponds to a location alongthe drillpipe; providing an indication to an operator based, at least inpart, on the at least one force measurement; wherein at least one of theforce measurements comprise at least one of a torque measurement or atensile force measurement.
 24. The method of claim 23, furthercomprising: offering advice on actions to the operator.
 25. A methodcomprising: receiving a first plurality of force measurements, eachforce measurement corresponding to a location along a drillstring, thedrillstring comprising a drillpipe, and where at least one forcemeasurement corresponds to a location along the drillpipe; creating afirst measured-value set comprising the first plurality of forcemeasurements and corresponding depths; receiving a second plurality offorce measurements taken at a different time from the first plurality offorce measurements, each force measurement corresponding to a locationalong a drillstring; creating a second measured-value set comprising thesecond plurality of force measurements and corresponding depths; andcreating a representation for an operator of both the first measuredvalue set and the second measured-value set.
 26. The method of claim 25wherein said representation comprises a graphical format.
 27. The methodof claim 25 wherein said representation comprises a textual format. 28.A method of analyzing one or more downhole properties, comprising:receiving, at a first time, a first plurality of force measurements,each corresponding to a location along a drillstring, the drillstringcomprising a drillpipe, and where at least one force measurementcorresponds to a location along the drillpipe; determining, based atleast in part on the first plurality of force measurements whether ornot a downhole condition is present; and wherein at least one of theforce measurements comprise at least one of a torque measurement or atensile force measurement.
 29. The method of claim 28, furthercomprising: receiving, at a second time, a second plurality of forcemeasurements, each corresponding to a location along a drillstring, thedrillstring comprising a drillpipe, and where at least one forcemeasurement corresponds to a location along the drillpipe; and whereindetermining, based at least in part on the first plurality of forcemeasurements whether or not a downhole condition is present, furthercomprises: determining, based at least in part on the first and secondpluralities of force measurements wherever a downhole condition ispresent.
 30. A method of analyzing one or more downhole properties,comprising: receiving, at a first time, a first plurality of forcemeasurements, each corresponding to a location along a drillstring, thedrillstring comprising a drillpipe, and where at least one forcemeasurement corresponds to a location along the drillpipe; determining,based at least in part on the first plurality of force measurements, ameasured property; determining an expected property corresponding to themeasured property; determining whether or not a difference between themeasured property and the expected property is greater than a maximumdelta.
 31. The method of claim 30, further comprising: receiving, at asecond time, a second plurality of force measurements, eachcorresponding to a location along a drillstring, the drillstringcomprising a drillpipe, and where at least one force measurementcorresponds to a location along the drillpipe; and wherein determining,based at least in part on the first plurality of force measurements, ameasured property, further comprises: determining, based at least inpart on the first and second pluralities of force measurements themeasured property.
 32. The method of claim 30, wherein the measuredproperty and the expected property are torques.
 33. The method of claim30, wherein the measured property and the expected property are tensiongradients.
 34. The method of claim 30, wherein the measured property andthe expected property are torque gradients.
 35. Ameasurement-while-drilling system for collecting and analyzing one ormore force measurements, comprising: a plurality of force sensors tomeasure forces at a drillstring, where at least one force sensor islocated along a drillpipe; a processor; and a memory, the memoryincluding executable instructions that, when executed, cause theprocessor to: receive, at a first time, a first plurality of forcemeasurements, each corresponding to a location along a drillstring, thedrillstring comprising a drillpipe, and where at least one forcemeasurement corresponds to a location along the drillpipe; determine,based at least in part on the first plurality of force measurements, ameasured property; determine an expected property corresponding to themeasured property; determine whether or not a difference between themeasured property and the expected property is greater than a maximumdelta.
 36. The measurement-while-drilling system of claim 35, whereinthe executable instructions further cause the processor to: receive, ata second time, a second plurality of force measurements, eachcorresponding to a location along a drillstring, the drillstringcomprising a drillpipe, and where at least one force measurementcorresponds to a location along the drillpipe; and when determining,based at least in part on the first plurality of force measurements, ameasured property, the executable instructions further cause theprocessor to: determine, based at least in part on the first and secondpluralities of force measurements the measured property.
 37. Themeasurement-while-drilling system of claim 35, wherein the measuredproperty and the expected property are torques.
 38. Themeasurement-while-drilling system of claim 35, wherein in the measuredproperty and the expected property are tension gradients.
 39. Themeasurement-while-drilling system of claim 35, wherein the measuredproperty and the expected property are torque gradients.